1. Field of the Invention
This invention relates to the treatment of gaseous streams containing appreciable quantities of nitrogen. It more closely relates to removing and recovering methane and higher boiling hydrocarbons from a gas stream, natural or synthetic, which contains large quantities of nitrogen, may contain acidic components such as CO.sub.2 and H.sub.2 S, and may vary in moisture content from dry to saturated. It specifically relates to the removal of nitrogen, which does not contribute to the heating value of natural gas streams in order to upgrade its heating value.
2. Review of the Prior Art
During recent years, there has been strong emphasis on the secondary and tertiary methods of recovering oil from formations where the primary oil-producing methods are no longer productive. Nitrogen injection for reviving these oil wells is not useful in most formations, but in some formations such as in the central Texas area, nitrogen injection has been successfully utilized for the recovery of additional oil.
After several years of nitrogen injections at high pressure, approximately 2000 psig, the nitrogen seems to have broken through the formations in many instances. In other words, nitrogen is coming out with the oil and it is separated from the oil at the separator. Previously, the associated gases were rich in hydrocarbons heavier than methane, along with substantial quantities of methane. The present dilution effect of nitrogen has caused the same associated wellhead gas to have an extremely low BTU content, thereby making it unsuitable for pipeline shipments. If the natural gas contains more than 3% of nitrogen, it is off specification for most of the world's pipelines.
This situation has caused the oil producer to curtail oil production because he cannot burn the nitrogen-rich gas, and environmental laws prohibit him from venting the associated hydrocarbons. The oil producer is thus limited to the choice of technology available to him for properly processing the associated gases from an oil well. The available technology involves cryogenic principles, thereby causing the purified gas to be uneconomical in the natural gas market, even after subsidization with the revenues from oil production.
Natural gas is a mixture of hydrocarbons, including methane, ethane, propane, and various various amounts of higher molecular weight hydrocarbons together with nitrogen and acid gases, such as CO.sub.2 and/or H.sub.2 S. A "dry" gas is one containing predominantly methane with some ethane, propane, and butane and having a very low hydrocarbon dew point. The heavier the hydrocarbons, such as pentane and higher homologs, that are present in the gas, the higher the hydrocarbon dew point. For pipeline transmission, enough of the heavier hydrocarbons must be removed to lower the dew point without losing too many BTUs to meet specifications. In the past, gas with large quantities of high molecular weight hydrocarbons have been passed through gasoline extraction plants and/or dew point control stations to lower the dew point. Also, frequently the gas has required conditioning to remove sulfur compounds and carbon dioxide.
A natural gas stream coming from the wellhead is also usually saturated with water at its ambient temperature which may have a range of 75.degree.-120.degree. F. so that its water content may vary from 20 pounds to more than 50 pounds per million standard cubic feet. However, difficulties are frequently met while pumping such natural gas, such as formation of ice and hydrates or the accumulation of water which can block the flow as well as cause corrosion, unless the water content is reduced to a value of less than 12 pounds, preferably less than 7 pounds, of water per million standard cubic feet of natural gas. In terms of dew point, a natural gas having a dew point of 30.degree. F., preferably 20.degree. F. or lower, is generally considered safe for transportation in a pipeline. Dehydration can be carried out under a wide range of pressures from 15 to 5,000 psig, but it is usually carried out at pipeline pressures of 500-1,500 psig.
Dehydration and sweetening of natural gas has been done with physical solvents, as taught in U.S. Pat. Nos. 3,362,133, 3,770,622, and 3,837,143, but always with an economic penalty from loss of hydrocarbons that were absorbed with the acid gases. Such losses are understandable when comparing the relative solubilities of the acid gases and of the hydrocarbons in physical solvents.
Such solubilities of hydrocarbon gases are disclosed in a paper entitled "High C.sub.2 -High H.sub.2 S Removal With SELEXOL Solvent", that was presented by John W. Sweny at the 50th Annual Gas Processors Association Convention, Mar. 17-19, 1980, the relative solubility of CO.sub.2 over methane in a mixture of dimethyl ethers of polyethylene glycol (DMPEG) is 15.0 and the relative solubilities of various hydrocarbons present in a natural gas stream are disclosed as varying from 6.4 to about 165, whereas the similar relative solubility of water is 11,000.
The Mehra process capitalized on the liabilities of the prior art processes by utilizing the relative solubilities of the hydrocarbons in physical solvents. Specifically, the Mehra process handles any natural gas, from very sour to entirely sweet, in the same equipment while simultaneously dehydrating the gas and recovering the heavier hydrocarbons with a physical solvent, as disclosed in U.S. Pat. Nos. 4,421,535 and 4,511,381 of Yuv R. Mehra, both of which are herein incorporated by reference. The compositions of its liquid hydrocarbon product and of its residue natural gas product can be readily adjusted in accordance with market conditions so that profitability of the extraction operation can be maximized at all times and on short notice. This process thereby produces a liquid hydrocarbon product having a composition which is selectively versatile rather than fixed, as in prior art processes.
The absorption principle leads to an alpha or relative volatility for methane with respect to ethane of slightly less than 5 for almost all known absorption liquids. However, the relative volatility for methane with respect to ethane in the presence of dimethyl ether of polyethylene glycol (DMPEG) is 6.4, indicating that it is more selective toward ethane than other absorption liquids. N-methyl pyrrolidone (NMP) and dimethyl formamide (DMF) have relative volatilities for methane/ethane of 5.3 and 8.5, respectively. However, the solubility of hydrocarbons in NMP is 0.03 standard cubic feet per gallon (SCF/gal) and in DMF is 0.04 SCF/gal; these are low when compared to 1.0 SCF/gal for DMPEG. The relative volatility of nitrogen over methane is 5.0.
Therefore, it is the combination of improved selectivity towards ethane and the hydrocarbon loading capacity of dimethyl ether of polyethylene glycol that makes it a superior absorption solvent for separating and recovering the components of a natural gas stream that are heavier than methane. The minimum qualifications for a physical solvent are a minimum relative volatility of methane over ethane of 5.0 (thereby defining its improved selectivity toward ethane over methane) and minimum solubility of 0.25 standard cubic feet per gallon of the solvent (thereby defining its hydrocarbon loading capacity). However, the ideal physical solvent would have a selectivity toward ethane over methane as high as 10.0, and simultaneously would possess a hydrocarbon loading capacity of about 3.0 SCF/gal. This combination also enables solvent flow rate variation and flashing-pressure variations to be particularly useful for flexibly producing liquid products, having selected hydrocarbon compositions.
This physical solvent is selected from the group consisting of dialkyl ethers of polyalkylene glycol, N-methyl pyrrolidone, dimethyl formamide, propylene carbonate, sulfolane, and glycol triacetate. The solvent is preferably selected from the group consisting of dimethyl ether of polyethylene glycol, dimethyl ether of polypropylene glycol, dimethyl ether of tetramethylene glycol, and mixtures thereof, and the solvent most preferably is dimethyl ether of polyethylene glycol containing 3-10 ethylene units and having a molecular weight of 146 to 476.
The glycol can be branched, such as polypropylene glycol. The basic difference between the behaviors of ethyl and propyl groups is the affinity for water for the ethyl and greater affinity for hydrocarbons for the propyl group. A mixture of dimethyl ethers of polyethylene and polypropylene glycol in various combinations is consequently suitable for recovering ethane plus heavier hydrocarbons from a natural gas. In such a mixture, the content of dialkyl ether of polyethylene glycol should be a minimum of 20% by volume, with dialkyl ether of polypropylene glycol being limited to 80% by volume maximum.
The versatility of the Mehra process is achieved by flexibility in certain operating conditions and by use of certain additional steps that are not used in the prior art. These conditions and steps are listed as follows, in order of importance:
(1) varying the flow rate of a physical solvent with respect to flow rate of the natural gas stream in an extraction column to produce the rich solvent;
(2) varying the flashing pressure for one or more of the successive flashing stages for the rich solvent;
(3) recycling the flashed C.sub.1 + undesirable gases from the first flashing stage and, selectively, also the second flashing stage to the extraction column;
(4) compressing, cooling, and condensing the flashed gases from the remaining flashing stages to form a crude liquid;
(5) rejecting and returning to the residue gas line selected components of the crude liquid, viz., methane (demethanizing), methane plus ethane (de-ethanizing), methane, ethane, and propane (depropanizing), or methane, ethane, propane, and butanes (debutanizing) in a stripping column for the crude liquid by:
(a) varying the pressure in the column, and PA2 (b) varying the temperature at the bottom of the column; and
(6) recovering the remaining components as the natural gas liquid product.
However, daily changes in market conditions may also cause the price of a single liquid hydrocarbon heavier than ethane to drop below its fuel price so that this hydrocarbon should be selectively rejected, but there was no way in the prior art or in these two patents of doing so without also rejecting all components of lower molecular weight. For example, if the price of ethane was below its fuel value, it could be rejected with methane, as taught in U.S. Pat. Nos. 4,421,535 and 4,511,585, but if the price of propane was below its fuel value while the price of ethane was above its fuel value, both of these hydrocarbons would have to be rejected together because no method existed for separating them. Accordingly, U.S. Pat. No. 4,526,594 of Yuv R. Mehra, which is also incorporated herein by reference, provides a process that is useful when changes in the market prices for individual hydrocarbons in liquid form cause the market price for an individual hydrocarbon liquid to fall below its fuel price. Such prices change on a daily basis so that it becomes advantageous to be able to extract all of the C.sub.2 -C.sub.5 + hydrocarbon liquids while rejecting and returning to the residue gas line one or more of the C.sub.2 -C.sub.4 hydrocarbons that are priced below their fuel values. The extraction plant can thereby be operated at optimum profit levels at all times.
The process of U.S. Pat. No. 4,526,594 accomplishes this selective rejection by subjecting the rejected components of the crude liquid to a second extraction with a portion of the same physical solvent to produce a gas stream of C.sub.1 or C.sub.1 +C.sub.2, which is returned to the residue gas line, and a second rich solvent stream which is singly flashed to produce an overhead gas stream and a liquid mixture which is regenerated to produce the physical solvent stream for the extracting. This gas stream is compressed, cooled, and condensed to form a second crude liquid stream. This liquid stream is split. The bottom portion, of C.sub.3 or C.sub.3 +C.sub.4 's or C.sub.4 's only, is sent to the residue gas line, and the top portion, of C.sub.2 or C.sub.2 +C.sub.3 or C.sub.3 only, is combined with the liquid product from the stripping column.
CO.sub.2 and H.sub.2 S have solubilities in DMPEG that are very close to the solubilities of propane and pentane in this solvent. Therefore, it is difficult to separate these acidic materials from the desirable gases when treating sour natural gas. The prior art has tended to perform this separation before removing hydrocarbons, thereby requiring large-capacity equipment and losing significant quantities of desirable hydrocarbons with CO.sub.2 and H.sub.2 S vent streams. Widespread usage of DMPEG has obviously been avoided.
In one of the embodiments of the Mehra process, CO.sub.2 and H.sub.2 S are allowed to remain with the desirable gases until final stages in the process where they are removed as liquids, thereby requiring smaller and less expensive equipment because the equipment's size is determined by mode of treating, i.e., in gas phase or liquid phase.
This treatment procedure requires the usage of substantially larger quantities of DMPEG than has been recommended by the prior art, since the quantity of C.sub.2 + hydrocarbons is generally larger than the quantities of CO.sub.2 and H.sub.2 S in a relatively sweet natural gas stream. There is, consequently, enough absorption capacity in the DMPEG stream when equilibrium is reached that the acidic materials in the recycle stream and in the sour natural gas can be completely removed, thereby producing a sweet methane-rich stream from the top of the extractor that meets pipeline specifications.
The advantage of this treatment method over those of the prior art is that a single plant can accept a very wide variety of natural gas streams, from very acidic to completely sweet, simply by utilizing the acid removal unit (e.g., an amines process) to a selective extent or even by by-passing it entirely. Although liquid-phase sweetening requires a lower capital investment and has lower operating costs than gas-phase sweetening, there are compensating factors in favor of gas-phase sweetening. These include the use and pumping of smaller quantities of solvent and the availability of maximum flexibility as to hydrocarbon composition in the liquid product.
It is preferred that amine processes (MEA, DEA, or DGA) be utilized for removing acid gas components (CO.sub.2 and H.sub.2 S) in gas phase before proceeding with this invention process. The sweet natural gas thus produced will be saturated with water vapor at the pipeline pressures and operating temperatures because any amine process is aqueous based and introduces water vapor into the natural gas stream.
Alternatively, acid gas components can be removed in the liquid phase downstream of processing according to this invention process by amine processes using MEA or DEA. For maximum flexibility of recovering ethane versus rejecting ethane while recovering all of propane plus heavier hydrocarbons in contrast to recovering propane versus rejecting ethane and propane while recovering all of butane plus heavier hydrocarbons, it is preferred that the sour natural gas stream be treated with aqueous amine processes in gas-phase operation in order to extract CO.sub.2 and H.sub.2 S components without losing any hydrocarbons.
Because natural gas is normally in a water-saturated state, much water must be extracted and carried by the solvent through one or more flashing stages of the Mehra process and then removed from the solvent by regenerating its entire volume at a temperature of about 300.degree. F., with subsequent cooling to ambient temperature. Such heating and cooling is quite expensive, and Ser. No. 637,210 provides a process for minimizing energy consumption for separating hydrocarbons and water from the solvent. The process is useful for an inlet natural gas stream containing at least 0.2 mol or vol. percent of C.sub.5 + hydrocarbons and comprises dividing the solvent stream and then selectively extracting the gas stream in a first extraction stage with the major solvent stream and in a second extraction stage with the minor solvent stream. The major stream contains up to an equilibrium amount of C.sub.5 + hydrocarbons, and the minor stream is lean with respect to C.sub.1 + hydrocarbons and dry with respect to water. The minor solvent stream or slipstream is generally all of the solvent that is regenerated. It is always less than 25% of the total amount of solvent and always sufficient to remove the water and C.sub.5 + hydrocarbons from the natural gas stream.
U.S. Pat. No. 1,768,521 teaches the two-stage absorption of natural gas, using a completely stripped absorption oil for feeding to a second absorber and the semi-rich oil from this absorber for feeding to the first absorber.
U.S. Pat. No. 1,934,029 describes a process for: (a) separating hydrogen from gaseous hydrocarbons by extracting a mixture thereof with a hydrocarbon oil, (b) separating hydrogen and nitrogen with ethyl ethers, acetic acid, and amyl alcohol, (c) separating hydrogen and sulfur dioxide with benzene and nitrobenzene, and (d) separating hydrogen and ammonia or hydrogen and carbon monoxide with alcohols.
U.S. Pat. No. 2,237,386 discloses a process in which three absorbers are utilized for successively removing hydrocarbons from an inlet gas stream by initially removing C.sub.5 + hydrocarbons and butane partially therefrom, next for completely removing butane and partially removing propane, and finally for completely removing propane and partially removing methane and ethane.
U.S. Pat. No. 2,521,233 teaches the removal of nitrogen from natural gas by using liquid ammonia as a solvent so that gas from a carbon dioxide well containing large amounts of nitrogen and carbon dioxide can be purified by drying the gas and cleaning it at about 700 psi and 70.degree.-110.degree. F.
U.S. Pat. No. 2,596,785 describes a method for enriching natural gas by initial removal of C0.sub.2 and H.sub.2 S, dehydration, and refrigeration to a temperature of -110.degree. F. before absorption with a lean oil to produce an enriched gas and a residue gas containing 60% nitrogen and having a heating value of approximately 450 BTU per cubic foot.
U.S. Pat. No. 2,663,169 relates to nitrogen-contaminated natural gases containing up to 40% by volume of nitrogen. The feed gas, after removal of water vapor and carbon dioxide, is at 305.degree. F. and is then sufficiently cooled such that nitrogen and C.sub.3 + hydrocarbons can be condensed and removed.
U.S. Pat. No. 2,814,359 relates to treatment of an off-gas from furnace manufacture of carbon black by absorption with dimethyl formamide. Nitrogen is absorbed, but hydrogen is not, so that these two gases are separated. In addition, carbon dioxide, acetylene, heavier acetylenes, and small quantities of other substances such as argon, benzene, vinyl acetylene, hydrogen sulfide, carbonyl sulfide, and carbon disulfide are similarly removed by absorption.
U.S. Pat. No. 3,255,572 is directed to scrubbing a natural gas containing hydrocarbons, carbon dioxides, and water with nitromethane absorbent and then with glycol absorbent in a two-stage absorption process. Nitromethane may also be used as a mixture with an inert solvent which is up to 50% by volume of the mixture. Suitable inert solvents include propylene carbonate, ethylene carbonate, N,N'-dimethylformamide, hydrocrylonitrile, formamide and gamma-butyrolactone.
U.S. Pat. No. 4,414,004 describes a process for removing condensable aliphatic hydrocarbons and acidic gases from natural gas containing these materials, wherein the natural gas is initially treated at superatmospheric pressure with polyethylene glycol dialkyl ethers, as the solvent, in a first absorption stage to effect absorption of the condensable aliphatic hydrocarbons. The natural gas from this first stage is then treated with the same solvent under superatmospheric pressure in a second absorption stage to completely or partly absorb the acidic gases. The solvent charged with the condensable aliphatic hydrocarbons from the first stage is treated with water in an extraction stage to form a hydrocarbon phase containing the condensable aliphatic hydrocarbons and an aqueous dialkyl ether phase, and the hydrocarbon phase is then separated from the aqueous dialkyl ether phase. The solvent charged with acid gases from the second stage is regenerated by expansion and/or stripping, and the regenerated solvent is recycled to the absorption stages.
U.S. Pat. No. 4,466,946 relates to a process for treating low quality natural gases containing 30-40 mol % of CO.sub.2, as is now produced by CO.sub.2 miscible flooding of low quality and sour gas reservoirs for enhanced oil recovery. According to one embodiment, at least a portion of the heavy hydrocarbons are removed by chilling, prior to a CO.sub.2 absorption stage that employs an aqueous alkanolamine solution. For example, triethanolamine absorption may be followed by diethanolamine absorption and then by sweetening by absorption with a mixture of polyethylene glycol dialkyl ethers.
There is consequently a need for a simple and inexpensive process that is operable at the wellhead to separate nitrogen from the natural gas. There is further a need for a process that can dehydrate, sweeten, and selectively separate C.sub.2 + hydrocarbons from methane in the natural gas during or prior to separating nitrogen therefrom.